Friday, February 23, 2018

Borehole Stability

Rock mechanics theory and practice are being stretched to their limit to solve severe borehole stability problems in the tectonically active Cusiana field of Colombia. The earth scientists' and drilling engineers' main challenge is estimating those most elusive of all earth parameters, subsurface stress and rock strength. What they find out can influence the entire development strategy of this newly discovered, giant field.

 Drilling and maintaining in-gauge hole remains one of the driller's greatest challenges. In-gauge, stable hole not only means trouble-free drilling, it also helps ensure that logs are of high quality, that the cement job runs smoother, and that every subsequent action in the well occurs to the operator's maximum advantage. Everything in the oilfield starts with the drillhole, so ensuring the hole possible is worth some thought and expense.

Fighting for hole integrity, the driller must monitor and juggle two key factors- mud chemistry and mud weight. Mud and formation must be balanced chemically, particulary in shales, to prevent the formation swelling against the drillpipe or sloughing into borehole. Simultaneously, a mechanical balance must be achieved to prevent two well-known phenomena - breakouts and formation fracturing -and ,as experts now suspect, maybe also a third phenomenon called shear displacement.  This article focueses on how the mechanical balance is monitored and achieved, and reviews the latest theories and measurement techniques in a case study from the newly discovered Cusiana field in eastern Colombia.

Rock in its natural state is stressed in three principal directions - vertically from the overburden, Sv, horizontally in two orthogonal directions. The two horizontal stresses are generally not equal - the maximum and minimum horizontal stresses are expressed as SH and Sh, respectively.

As a borehole is driled, hydraulic pressure of the drilling mud must replace the support lost by removal of the original column of rock. But mude pressure being uniform in all directions cannot exactly balance the earth stress. Consequently, rock surrounding the borehole is distorted or strained, and may fail if the redistributed stresses exceed rock strength.

One failure mechanism is tensile failure. This occurs when hydraulic pressure of the mud becomes too high, causing formation stress at the borehole wall to go into tension  and exceed the rock's tensile strength. This fractures the rock along a plane perpendicular to the direction of the earth's minimum stress, generally one of the horizontal stresses, and potentially causes lost circulation.

Alternatievely, the formation can fail in compression. This is commonly predicted using the Mohr-Coulomb model, in which the factors controlling failure are the minimum and maximum stresses at the borehole wall- the intermediate stress is assumed to have no effect. Compressive failure may be caused by too low or too high a mud weight. In either case, formation caves in or spalls off, creating breakouts. The debris can then accumulate in the borehole leading to stuck pipe or even hole collapse.

The third, recently discovered mechanism of mechanical instability is shear displacement. In this, mud pressure is high enough to reopen naturally existing fractures that intersect the borehole. As the fracture is opened, stresses along it are temporarily relieved, and opposite faces of the fracture can physically shear, creating a small but potentially dangerous dislocation in the borehole. The phenomenon was first identified by Elf geologist Maury and Sauzy in agas field in the southeast France.










 The bottom line for the driller striving to maintain a stable hole is choosing the right mud weight. First, mud weight must be sufficient to exceed formation pore pressure, not a mechanical stability issue but essential for preventing kicks. Second, it must be high enough to avoid the low mud-weight mode of compressional failure. Third, it must not be too high that the formation fails in tension or in the high mud-weight mode of compressional failure. Fourth, it must not be too high to initiate shear displacement.

Steering a middle course would be challenging enough in a thick, homogeneous bed, but in reality drillers must maintain stability over long openhole sections with varying lithology, strengths and stresses. And generally speaking, the middle course is harder to find the more the well is deviated. When the going gets too rough, casing gets set. But while drilling continues, all available measurements and knowledge, particualry experience drilling nearby wells, must be applied to choose optimum mud weight.

The key parameters for evaluating stability are simply the three principal components of earth stress and rock strength parameters defining tensile and compressional failure. Once these are known, computer programs seedily calculate the principal stresses at the borehole wall, and predictions of failure can be obtained. But both earth stresses and rock failure are extraordinarily difficult to assess accurately, and a successful resolution must use an integration of all available methods of obtaining them. Most of these methods have been brought to bear with some success in the Cusiana field where drillers have faced immense drilling problems.

The Cusiana field lies in the eastern foothills of the Andes. Discovered in 1991 by BP exploration company (Colombia) Ltd. with partners Total Compagnie Francaise des Petroles and Triton Energy Corp., the field promises to be in the top 50 oil reserves of the world. Drilling the discovery wells, though, proved a driller's nightmare with mechanical stability problems causing stuck pipe, damaged casing and sidetracks. BP estimates that approximately 10% of well cost is spent coping with bad hole. Average rig time to reach oil-bearing sediments at more than 14,000 ft [4200 m] has been 10 months. 

Although both chemical and mechanical factors inevitably contribute to bad hole in the Cusiana field, the operators had no doubt that mechanical stability was the prime cause. The field lies on the eastern flank of the Oriental Andes cordillera, an area being actively compressed by the eastward thrust of the Pacific "Nazca" plate and the more southeasterly thrust of the Carribean plate. 

Three fault blocks are being compressed in the Cusiana region with faults striking parallel to the cordillera - the Yopal block under the cordillera, the Cusiana block containing the reservoir, and the Llanos block under the plains to the southeast. The reservoir is situated in the Cusiana block between the Yopal and Cusiana thrust faults.

Generally, in quiescent geological areas, vertical stress caused by the weight of the overburden is greater than either of the two horizontal stresses. Geologists suspected this might be the case in the Yopal block, where there seemed to be enough minor faulting to relieve the large horizontal stress induced by tectonic deformation. But in the Cusiana block and particularly the Llanos block, it was thought that horizontal stress in the northwest-southeast direction was still high, almost certainly greater than the vertical stress. 

 Drillers became convinced of this as severe drilling problems developed in the Carbonera formations in the middle of the Tertiary zone. The Carbonera formation is an interbedded sequence of sands, mudstones and shales comprising eight units. As a result, a task force comprising BP, Total, Triton and Schlumberger experts was convened to measure and understand the Cusiana stress field and attempt to resolve the drilling problems.

The techniques that are being used to evaluate the Cusiana stress field are multifarious. Some remain to be implemented, others already have been. They include: 
  • computer simulation of the region's tectonic deformation.
  • Analysis of the breakouts on caliper logs to determine the direction of minimum horizontal stress.
  • Analysis of oriented cores to evaluate stress direction and possibly magnitude.
  • Use of extended leakoff test to evaluate horizontal stress magnitudes and calibrate an earth stress model.



BP's computer simulation of tectonic deformation in the three blocks confirmed that in most of the region, horizontal stress in the direction of tectonic compression -that is, in a northwest-southeast direction, normal to the cordillera -was the maximum stress. With no compression, vertical stress was greater than the normal horizontal stress. But with some compression, normal horizontal stress increased, eventually becoming larger than the vertical stress. 

In the field, the direction of least horizontal stress can be confirmed by observing breakouts using caliper logs. Breakouts, caused by the borehole being in compressional failure, have been observed worldwide to cause ovalization of the borehole with oval's long axis parallel to the minimum stress. In several Cusiana wells, breakouts have been evaluated using the dual caliper and borehole drift measurements of dipmeter and resistivity imaging tools. The caliper pairs, oriented at 90 degree , provide information about borehole enlargement. The tools' navigation system measures orientation and deviation of the borehole and establishes tool azimuth.

Breakouts can be picked automatically from logs using the Breakout Orientation Log (BOL) program. This reviews the caliper pairs and flags zones where one pair is close to bit size while the other is significantly larger. Furthermore, their difference has to materialize quickly versus depth to distinguish potential breakouts from irregular washout. Once flagged, the long axis of the breakout can be oriented with the borehole drift and tool azimuth measurements. The results in the Cusiana field have a striking consistency, showing breakout and therefore direction of minimum horizontal stress oriented between 30 degree and 60 degree that is, southwest-northeast.



A more common and certainly more reliable method of measuring earth stress is through extended leakoff, or minifrac tests. Normal leakoff tests are systematically performed by drillers to investigate rock strength after casing is set. The hole is drilled out several feet below casing and borehole fluid pressure is increased by pumping small quantities of additional mud into the well. At first, the pressure builds up linearly. But when formation at the borehole wall cracks and mud begins to leak off, presssure increases less fast. The point where this change occurs gives the leakoff pressure. In the Cusiana field, BP has so far performed 35 leakoff test in 11 wells.

The extended leakoff test is a riskier exercise for the driller and one not contemplated during the trials of drilling the current Cusiana wells. As before, mud is pumped until intial failure of the formation at the borehole wall. But then more mud is pumped to create full fracture - this occurs at the slighty higher breakdown pressure, Pbd. 





 

Friday, February 2, 2018

Structural Interpretation in Offshore Congo

Petroleum exploitation begins with geologist and geophysicst exploring unknown territory with few wells for guidance and no visible sign of oil and gas. Their task is to uncover the best prospects and decide whether oil companies should commit to millions of exploration dollars. A key tool is structural interpretation of seismic data. A survey shot in deep waters off the Congo mainland shows how geologist apply this technique. 



 Play in exploration context describes a geological configuration that favors the accumulation of hydrocarbons. Plays and their associated prospects are what exploration geologist sped most of their professional lives looking for.

 Until oil or gas is discovered, plays exist mostly in the mind. Focusing on one or another of the earth's basins, explorationists search for that seemingly impossible concatenation- source rock, migration path, reservoir and seal. Each vital ingredient must be present, both at the correct physical location and at the right time.

 Source rocks rich enough in organic material must have been buried and heated to sufficiently high temperature and long enough to form petroleum. Petroleum migrates upward, so there must have been a conduit to guide it. And a porous, permeable reservoir rock capped by impermeable rocks is required to receive and trap the fluid. Finally, the ensuing geological evolution - commonly several tens or even hundreds of million years - must have left the reservoir and seal intact. 

As explorationists focus on a sedimentary basin, this juxtaposition of geological coincidence occupies the mind. Every scrap of evidence is used to refine the notion of how the basin might have evolved and whether the structural and sedimentary history might favor a play. Outcrop geology, satellite imagery, magnetic and gravity surveys, and especially seismic data contribute to the interpretation process. This article shows how various plays in offshore Congo crystalized in the minds of geologists as they reviewed a nonproprietary seismic survey shot in West African waters.

Geologist first became interested in the Congo in 1928, attracted by tar seepages near Pointe Noire on the coast and knowledge that the subsurface contained thick deposits of salt- salt intrusions provide a classic trapping mechanisms for hydrocarbon accumulation. The salts had been identified in numerous boreholes drilled for potash mining exploration.

Oil was discovered at Pointe Indienne, 20 kilometers north of Pointe Noire, in 1959. But further onshore exploration proved fruitless - some oil shows , but nothing of commercial value. In the late 1960s, an Elf/AGIP partnership discovered oil offshore. Further successes yielded five offshore fields and oil production  from the Congo now exceeds 115,000 barrels per day. Recoverable reserves are currently estimated at more than a billion barrels. 

The GECO_PRAKLA nonproprietary survey of 1990, which forms the basis of the interpretation described in this article, covered 15,000 square kilometers. The survey ventured from shallow water at the edge of the continental shelf, where oil plays were known to exist, to depths up to 2000 m [6560 ft]. This is deeper than the current limit of commercial exploitation, but the deepwater data were nevertheless crucial for elucidating basin structure and migration pathways from deep in the basin. The survey lines were designed to connect with previous surveys conducted closer to the coast and intersect any exploration wells where precise lithological data would be available.

The offshore basins of the Congo form part of the West African Salt Basin, a large collection of basins stretching 2000 km from south Cameroon to Angola. The salt was deposited during Aptian times about 120 million years ago when the rifting of South America from West Africa gradually evolved into a full-fledged drift. Later salt movement would create anticlinal folds capable of trapping hydrocarbons. 


The story , begins thirtly million years earlier during the Late Jurassic. At this time, extensional faulting and subsidence took place in the part of the Gondwana supercontinent that would eventually become both the east coast of South America and the west coast of Africa. Further stretching or extension in the Early Cretaceous led to the formation of a large-scale rift along the future western Africa and eastern Brazilian margins. A modern parallel is the Great Rift Valley extending from the Red Sea to the Zambesi River.





Initially, the rift and its basins were above sea level and isolated from the ocean. Large lakes formed in which sandstone and shales accumulated. Some shales were deposited in oxygen-deficient water, allowing preservation of organic matter. These formations are the source for billions of barrels of oil found in the West African basin. 

By Aptian times, continued subsidence and a rise in global sea level permitted incursion by the sea. At first, this was intermittent, with the sea alternately entering and receding from the basins. This created ideal conditions of repeated evaporation and marine flooding to create thick deposits of halite, the Aptian salts.

Later, during the mid to Late Cretaceous, the area was definitely submerged and continental breakup of Gondwana led to a separation, or drift, of South America from Africa. Whreas the basins had previously been linked on one continental plate, now they were separated by a widening tract of ocean, as the Atlantic opened through injection of new oceanic crust at the mid-ocean ridge. Sedimentation was now marine, with thick deposits of limestone, sandstone and shale. Further subsidence took place in the Late Tertiary and was probably associated with faulting related to the collision of the Eurasian and African plates.

This big picture the interpreters learned from extensive research into the region's geological history. Another card in their hand was knowing which formations had produced oil shows during drilling in the area , which of these had produced commercially, and which formation was the most likely source for the shows - the most important was the Marnes Noires, or black marls, continental deposits formed under lacustrine conditions late in the rift phase and prior to the invasion of sea water. 

The majority of commercial reservoirs in offshore Congo occurs in sandy and dolomitic rock deposited during the early drift phase in the mid-Cretaceous, with structural traps created by movement of the transition-phase Aptian salts. Noncommercial oil shows have been found aplenty in rift and transition rocks of the Lower Cretaceous , but no oil has been tested in Upper Cretaceous or Tertiary formations.

The interpreters knew the source of oil, therefore, and in general how it most  likely migrated and became trapped. What they did not know -and what they sought during the interpretation - was information on the three-dimensional structure of the deepwater Congo sediments -specifically the location, general distribution and size of likely hydrocarbon prospects. Their immediate goal was to identify target areas suitable for detailed mapping with more closely spaced surveys. 

We rejoin our interpreters as they inspect the survey's processed and migrated sections and begin the critical task of identifying formation tops - the lenghty data processing was previously accomplished.










 


 Scanning the sections, the interpreter will also note major structural features such as listric faulting and salt bodies, and begin the highly skilled task of constructing a picture of the subsurface, all the time drawing and updating conclusions on a working map. Perhaps the interpreter's most cherished skill is this ability to visualize in three dimensions.

The basis of structural seismic interpetation is the loop method, in which a seismic reflector representing a geologic horizon is mapped around a series of intersecting sections and then back to original section.Closing the loop is easier said than done. Tracing the continuity of a reflector can be tricky across a fault and sometimes impossible if the formation pinches out laterally or has been eroded to form an unconformity. Problems may also occur in areas of steep dip, where 2D migration on each section fails to image complex three-dimensional structure correctly, producing a slight mistie.

Typically, the interpreter plots the major geological units from the logs on the seismic section at the well location to obtain the best correlation. Lithology changes observed on the logs assist the correlation process. For example, a slow formation such as mudstone overlying a fast formation such as tigh limestone typically correlates with a white band or trough on the seismic section. Conversely, a fast formation overlying a slow formation generally correlates with a black band or peak.  

Once the best correlation is found, the interpreter colors the section at the well location according to the geological units on the log.

Some interpreters identify all faults on the section (red marking) and then track reflector continuity. Others may concentrate on reflectors and reflector terminations- onlaps and truncations - concentrating on the stratigraphy and marking in only those faults that bear on the work at hand.

In both example sections, the thin Aptian sand (orange) forms a boundary between the rift sediments below and the drift sediments above. Overlying the sandstone, the salt (purple) intrudes into the overlying sediments, creating structural traps for oil generated in the Marnes Noire below.

The first section that lies parallel to the direction of geological dip cleary shows fault blocks in the deep rift sediments and large-scale listric faults in the shallower drift sequences. A listric fault has a pronounced curved slip face. In this example, the sediments to the left (southwest) of the fault have been displaced downward and rotated clockwise. 





The interpretation seems clean and finished, yet questions often remain. Formation tops may be uncertain, particulary in the deeper section beyond the range of well control and where seismic data lose their resolution. The exact shape of the all important salt intrusions may be subject to different interpretations. A solution for resolving these cases lies with magnetic and gravity data, acquired concurently with the seismic data. 



At this point, all the factors necessary to pinpoint plays are at hand. The burial history confirms the potential of organic-rich horizons as source. Detailed comprehensive and mapping of basin structure reveals likely migratory paths and trapping mechanisms. The thickness maps indicate the distribution and geometery of sediment bodies and assists in recognizing commercially interesting reservoirs. Deciding the location of plays now demands of the interpreter a juggling of these factors and the picking of locations and depths where all indications appear simultaneously favorable. The result is a play map that oil companies can use to decide










Friday, January 26, 2018

Seismic Structural Imaging

Ask a geophysicist for a simple definition of structural imaging and you might get an analogy like this, echoing the parallel between optics and acoustics. But in direct terms, structural imaging boils down to this:  the branch of seismology in which processed seismic data undergo additional passes to create a large-scale picture of the subsurface. Its goal is to provide a map to locate traps and plan a drilling strategy for optimal drainage. 

Structural imaging lays the foundation for other seismic techniques that investigate progressively smaller features. After structural imaging, seismic stratigraphy jumps to the next level of detail, characterizing the arrangement of layers within rock formations. Next, lithostratigraphic inversion attempts to describe lithology of individual rock layers and evaluate properties and distribution of pore fluids, through analysis of variation of seismic signal amplitude with spacing between source and receiver, called offset. The quality of these finer-scale techniques rest largely on the quality of structural imaging. 

Today, structural imaging is advancing on two fronts. One is improving image quality of conventional structures-their position and shape become known with greater accuracy. The other is the abilty to image areas of more complex structure associated with large, rapid changes in velocity. Examples are low-velocity layers, structure below salt or gas, multiply folded and faulted formations. Understanding of these difficult settings promises to better quantify reserves in established fields and help define new prospects that eluded more conventional approaches.  

In all but the simplest geologic settings, imaging with seismic energy has three fundamental problems: the image starts out blurry, has the wrong shape and is in the wrong place. These problems are  caused mainly by refraction -bending of rays as they pass through rocks in different velocity- and diffraction of seismic energy as it passes through rocks of different velocities, shapes and thicknesses. To make the image interpretable, seismic energy must be focused into a sharp, correctly shaped image, and the image moved to the correct lateral and vertical position. The sharper the image of a structure and truer its shape and position, the more accurately the structure can be evaluated and drilled. The method of sharpening, shaping and relocating images is loosely termed migration, often considered synonymous with structural imaging.

Mathematically, migration is performed by various solutions to the wave equation that describe the passage of sound through rock. Called migration types, these numerous solutions or algorithms often take the name of their authors (Gazdag,Stolt) or the type of solution (finite difference, integral).
Migration types may be thought of as a family of tools, each with shortcomings and advantages. Choice of the optimal type is not always obvious and relies on the experience of the seismic practitioner.

Types of migration are applied in a broader category of migration called class: poststack or prestack, two-dimensional or three-dimensional (2D or 3D), time or depth. These classes form eight possible combinations. The trend in imaging is from postack to prestack, 2D to 3D and time to depth migration. This trend is best understood by examining the strengths and weaknesses of these classes. 

Poststack migration, still the most common form, assumes the section built of stacked traces is equivalent to a zero-offset section, meaning each trace is made as if the source and receiver are coincident. Chief advantages of poststack migration derive from stacking: compression of data, removal of multiples and other noise, and fast, inexpensive processing.  Postack migration holds up even in fairly strong lateral velocity variation, stacking breaks down and prestack processing is required. A limitation of stacked data is its removal of true amplitude information.

Prestack imaging is done on unstacked traces, taking 60 to 120 times longer than postack imaging, but with potential to retain amplitude variation with offset (AVO) and phase changes useful for later analysis. Prestack time migration is preferred when two or more events occur at the same time but with different stacking velocities.  Prestack depth migration is advantageous when velocities in the overburden or the target are complex, but requires large computer resources and remains rare. However, as massively paralel computers become more widely available, migration technology will shift toward prestack depth migration.

In 2D migration, energy reflected only in the plane of the section is correctly imaged, whereas 3D migration uses energy from both in and out of the plane of the section. In general, 3D migration will have higher resolution because it can move energy from outside the plane back to its correct position. The cost of higher resolution, however, is  greater acquisiition costs with longer processing time - what takes days in 2D might take weeks in 3D.

The choice of 2D or 3D migration is first determined by acquisition geometry. Data acquired with a 2D scheme- a single acquisition line with shot and receivers in a line - can only be 2D migrated, but 3D data can undergo 2D or 3D migration. An inexpensive, fast approximation to 3D migration is 2D migration in orthogonal directions, called two-pass 3D migration. It is strictly correct only for a constant-veloctiy earth, but errors are small if the vertical velocity gradient and dip angle are small.

Time and depth migration differ on several levels. In simplest terms, time migration locates reflectors in two-way travel time - from the surface to the reflector and back as measured along the image ray- whereas depth migration locates reflectors in depth. A migrated seismic section with a time axis, however, is not necessarily a time migration. A depth migration may be converted to time. This is sometimes done to compare velocity modeling for depth migration with velocity assumptions used for time migration.

The significant difference between time and depth migration is the detail with which they view the behaviour of sound in the earth. To time migration, the earth is simple in both structure and velocity; to depth migration, it may be complex. Time migration assumes negligible lateral variation in velocity and therefore hyperbolic moveout. Using only stacking velocity , or some approximation, time migration can make sharp and correctly shaped and positioned images - if structure and velocity are generally simple. Time migration can handle some complexity of structure , but only limited variaton in velocity. 

When velocity and structure become obviously complex, rays are bent, producing nonhyperbolic arrival times and distorting the resulst of time migration. Reflectors become blurry, move to the wrong place or become too long. Accounting for this ray bending requires what is called a macro model - a model of velocities between reflectors. This is needed mainly to eliminate lateral positioning error caused by refraction, but also to sharpen the image. Construction, revision and verification of this macro model are the goals of depth migration, are the main contributors to its difficulty and cost. Depth migration is also more sensitive to errors in velocity than time migration.



Picture above: Visualizing a North Sea salt diapir structure with 2D time migration, depth migration and depth migration output in time. Colors denote the interval velocity field determined prior to depth migration. The velocity model permits a more certain migration by including lateral variations. In the posstack time-migrated section, reflectors are poorly defined, on both the flanks and base of the diapir. Definition improves in the prestack depth migration, performed with the velocity field shown. Finally, for comparison between the prestack depth and time migrations, the depth migration output is converted back to time, revealing a marked improvement in definition of the diapir flanks and base.

 Although time migration handles only simple problems exactly, it remains the dominant technique in exploration, and usually lays the foundation for the depth migration macro model. In the production setting, some operators prefer to strecth time migration to the limit before jumping to depth migration. Still, depth migration has become a valuable tool because it is the only one that can handle the most difficult problem in imaging - strong, rapidly varying lateral changes in velocity. Depth migration also remains the focus of most imaging research. 

When is depth migration needed? Or, to put it another way: When is the velocity field complex enough to mislead time migration? For many operators, a step before depth migration is a processing step to convert time-migrated section to depth using image-ray depth conversion. This procedure uses an image ray, which is shot downward perpendicular to the surface and is bent by an amount predicted by Snell's law applied to the velocity model. The ray passes through the correct lateral position of an event, which in the time migration would appeear vertically below the starting point of the ray. If the image ray strikes the reflector a considerable lateral distance from the starting point, velocity variation may be interpreted to be sufficient to warrant depth migration.



In many areas, the decision to use depth migration usually arises when imaging the near-vertical flanks of salt domes. In this setting, BP tests the macro model with ray tracing. if the depth or lateral position of the image is not displaced far enough to affect well placement, then BP does not bother with depth migration. To preserve steep-dip events, BP is careful not to finish processing with a low-cut filter (5 to 40 Hz). In removing noise, the filter may inadvertently erase low-frequency, steep-dip events. 

Selection of the approriate type and class of migration is only half the story of imaging, however, and probably the less important half. The main concern in imaging is the engine that drives the depth migration algorithm - the velocity macro model. 



The macro model is a numerical description of the subsurface on the scale of hundreds of meters. It contains either two-way travel time or depth to the main reflectors and the velocities and densities between them. It describes the acoustic propagation characterics of the subsurface and is used for depth migration to include ray bending. In other words, the macro model functions as the air traffic controller for the migration algortihm. It tells the algorithm how far to move the reflector - up a little, down, to the left or righ, or hold the line. Inadequate knowledge of velocity results in the image being under- or overmigrated, misplaced or blurred. Even the most advanced migration algorithm will fail to focus the image if directed by a flawed macro model.


Techniques of macro model building are controversial, proprietary and fast evolving. It remains the weak link in the depth migration, so attention today focuses on increasingly sophisticated ways to model, update and verify velocity for depth migration. The cost and computation time of these techniques increase with their capability to handle large, rapid changes in velocity.


A starting point is stacking velocity, obtained for conventional time processing. Stacking velocity is calculated from the difference in arrival time at different offsets, assuming the layers over the reflector have a constant velocity. Stacking velocity values are often inaccurate because they are an average over a large volume of rock, which often has nonuniform velocity. Stacking velocities may be constrained with data from sonic logs or previous seismic data. Still, stacking velocities may provide the best, first macro model. 


A first-guess model of the earth is usually developed by picking main reflectors from a poststack time migration. Times are assigned to each reflector and velocities to intervals between reflectors. A first order approximation is the computation of constant velocity values between reflectors. Now, workstations readily permit estimation of velocity gradients vertically between reflectors and sometimes horizontally along the event. The macro model may then be used to make a synthetic seismogram based on part of the model, which is iteratively modified until the synthetic matches the measured seismic data. 

















Thursday, January 11, 2018

Seismic While Drilling

Seismic while drilling promises elegant solutions to some limitations of conventional borehole seismics. But so far, it has failed to grab a significant slice of the market. Recent advances may create new opportunities for the technique.

 The aim is to turn conventional borehole seismics on its head. Instead of locating seismic sources on the surface and conveying receivers downhole, seismic while drilling uses bit vibrations as a downhole source and surface geophones to measure signals. This inversion promises timely seismic information without interrupting drilling and without deploying any downhole hardware. Further, the service may be employed in environmetally sensitve areas where surface seismic sources are disruptive - for example, in jungle roads built specially to accomodate sources. Despite these advantages, a widely-used seismic-while-drilling service has so far proved elusive.

This article outlines the princlpes of seismic while drilling and its potential uses, looks at developments to date, and examines how recent research initiatives are rekindling interest in the technique.






The principles

Well location is usually selected using surface seismic images. Once drilling is underway, it is useful to know the bit's position relative to the seismic section. However, this information is not easily available because the vertical axis of the seismic section is measured not in distance but in "two-way-time" - the time the seismic waves take to travel through the earth, bounce off a subsurface reflector and return to surface.

To relate the position of the bit to the seismic section, it is necessary to convert the vertical axis from time to depth. This conversion requires knowledge of the velocity of seismic waves through the formation. Velocity varies significantly with rock type and usually has to be measured, rather than modeled, using a combination of sonic logs and borehole seismics of a well after it has been drilled. 

The theory of borehole seismics has been known for many decades. At its simplest, a geophone deployed on wireline records the time that seismic waves take to travel from a surface source to a receiver at known depth in the well. These times are doubled to tie in with two-way time on the surface seismic section. This simple service is known as a "checkshot" survey.

But there are subtleties that add significantly to the usefulness of borehole seismics. Good quality data, sampled finely and in sufficient depth, enable a vertical reflection image or vertical seismic profile (VSP) to be created. In a basic VSP survey, the seismic source is static and the geophone  is moved to different levels in the well. The image may be displayed either in time, to match the surface seismic section, or in depth, to match wireline logs.

Alternatively, the geophone location may be fixed and the surface source moved along a line that "walks away" from the rig. Walkaway VSP produces an image of the subsurface with lateral coverage that is typically between half and a quarter the well depth. In deviated wells, various combinations of VSP and walkaway VSP may be employed to provide the required images.

Today, borehole seismics delivers a range of high-resolution images. However, like all wireline-delivered services, drilling must stop and the drillstring must be removed prior to running the survey. Therefore, borehole seismics is typically carried out during openhole logging, usually just before casing is run. The results certainly offer useful information, but this may be too late.The well may already be in the wrong place - for example, on the wrong side of a fault subsequently revealed by walkaway VSP - and a costly sidetrack may be needed. Furthermore, it may be expensive or impossible to locate sufficient surface sources to create a satifactory walkaway VSP image.

 In seismic while drilling, compressional waves emitted by the active bit radiate both directly to surface and downward from the bit, reflecting off formation boundaries. By using surface geophones to detect this sound, the inverse checkshot, VPS and walkaway VSP surveys may be obtained. 

  These techniques offer several advantages over conventional borehole seismics: drilling need not stop and, because the measurements are made continously, the information allows well trajectory decisions to be made before it is too late. Further, using the bit as a source may make it practical to perform large-scale borehole seismic jobs where surface sources are impractical - for example in towns or environmentally sensitive areas. However, seismic while drilling presents significant technical challenges. The signal emitted by conventional seismic sources is well controlled - either an impulsive explosion or a sweep from a vibrator of known signature - making the time between its emission and detection relatively easy to determine. On the other hand, the bit's signal is essentially continous and uncontrollable. A geophone on surface records continous seismic radiation as it is transmitted through the ground.


In addition, the environment around a drilling rig is very noisy. The comparatively low-level energy of the drillbit seismic signal is often completely submerged in noise. Onshsore, the geophone traces include several noise components. Some noise that correlates with seismic signal is caused by bit vibrations travelling up the drillstring and the fluid-filled annulus and then "rolling" along the air-ground interface to the geophones-this is called correlated ground roll. Uncorrelated ground roll comes from the vibrations of surface equipment like the mud pumps and engines. Random noise is caused by events like a passing truck or train. 

The challenge is to recognize the unknown and variable signature of the bit, to improve the signal-to-noise ratio and to convert a continous emission to one in which discrete seismic events may be recognized.








For seismic while drilling, the filter exploits differences in the moveout of components within the traces. Ground roll approaches the geophones from the side and exhibits moveout across the array. However, the wavefront of the seismic signal approaches the array from below, has zero moveout and is in phase. By using these differences in moveout to distinguish between different parts of the trace, the adaptive filter effectively attenuates the ground roll, while allowing the seismic signal to pass. 

Random noise may be removed by cross-correlating the individual geophone traces with the average of the two traces measured by the accelerometers on the drillstring. This crosscorrelation also gives the time shift between accelerometer and geophone signals- the difference in signal velocity through the drillstring and formation.

 Determining formation velocity also requires knowing the drillstring travel time. As already noted, the many components in the string complicate calculation of this travel time and a number of methods have been proposed - like Elf's double crosscorrelation process.

The continous checkshot system uses a new technique called drillstring imaging, also devised at SCR, to model changes in the acoustic impedance of the drillstring, giving a better understanding of the velocity of the signal through the drillstring. The time shift and the drillstring travel time are then used to compute the formation travel time.










The processing capitalizes on the relative abundance of geophone data and tracks the wavefront as it travels through the formation, potentially estimating the bit signal and the earth's response without using accelerometer data. However, by employing the accelerometer input, data may be compressed, making it feasible to store the massive volume of information collected over three or four days.

Each trace contains a common bit signature, and noise that varies from trace to trace. With time-delay curves, stacking and deconvolution filtering, new signals are created that represent what the traces would have looked like if the source had been a noiseless pulse - the earth impulse response. This converted form is then migrated to create an image.





Monday, January 8, 2018

Overcoming Limitations of Sequence Stratigraphy

Sequence stratigraphy has proven useful for petroleum exploration, but it is commonly misapplied. There is controversy over whether the technique can be applied to carbonate systems since it was designed to explain sand-shale systems. Some experts maintain that sequence stratigraphy is easier in carbonates because carbonates are extremely sensitive to sea level change. There is unanimous agreement, however, that low sedimentation rates often pose special problems. When sedimentation rate is moderate to high, layers within a sequence are tens to hundreds of meters thick, comfortably within the resolving power of a typical seismic wave. But when sedimentation rate is low, several sequences might fit within a seismic wavelength. Sequence stratigraphy cannot be confidently applied here, but it has been done countless times. A useful interpretation in thinly-bedded regions requires abandoning small-scale features and concentrating on larger scale, longer term processes that control the generation of sequences. 

 With this in mind, Vail and coworkers proposed a hierarchy of stratigraphic cycles based on duration and amount of sea level change. Duval and Cramez at TOTAL Exploration worked with Vail to provide subsurface examples and to expand the application to hydrocarbon exploration. The hierarchy assigns frequencies to the mechanisms of eustasy  enumerated by Fairbridge, viewed in light of plate tectonics. The first-order cycle, which is the longest, track creation of new shorelines resulting from the breakup of the continents. The second-order cycle is landward and basinward oscillation of the shoreline that lasts 3 to 50 million years. This oscillation is produced by changes in the rate of tectonic subsidence and uplift, caused by changes in rates of plate motion. 
Both first - and second order cycles may cause changes in the volume of the ocean basins resulting in long-term variations in global sea level. The third-order cycle is the sequence cycle, lasting 0.5 to 3 million years. Fourth- and higher order cycles may be correlated with periodic climatic changes.

The following example, with its low deposition rate, approaches the limit of interpretation in terms of third-order cycles. It comes from the Outer Moray Firth basin in the UK sector of the North Sea, where the initial basin shape, tectonic activity and variation in the rate of deposition add a twist to the interpretation.

Stratigraphic interpretation of the last 65 million years of sediments in the Outer Moray Firth is more difficult than in the Gulf of Mexico because slower deposition in the Central North Sea resulted in thinner units, many of which cannot be resolved by seismic waves. During this period, the Outer Moray Firth has 17 sequences totaling 5000 feet of sediments, compared to the Gulf Coast, with 10 sequences totaling 9000 ft. In the North Sea, however, depositional processes juxtaposed a variety of lithologies, provide reliable calibration points for accurate conversion of logs from depth to time using synthetic seismograms. 





In the Gulf of Mexico, this conversion is typically done with only nearby checkshots; sands and shales commonly show periodic alternation with depth at wavelength that make comparisons between seismic sections and synthetic seismograms nonunique. 

 Stratigraphy study is always preceded by structural interpretation. In addition, a paleogeographic interpretation of the Outer Moray Firth shows that late in the Cretaceous period - when the sequences under study began to deposited - a smooth basin floor sloped gently from northwest to southeast. During a relative fall in sea level, sediments were deposited as slope fans. Their seismic expressions indicate lobes with channels and some chaotic flows- large scale slumps with jumbled seismic character. As sea level rose, a wedge of out-building deltas was deposited. Sea level maximum is associated with a depositional hiatus, shown only as a thin line. Deposits synchronous with this surface may be found on what is now land in Europe, but in the basin, sediments that correspond to periods of high relative sea level are rare. 

 Why are elements of the classic Vail model missing from this sequences in this basin? One explanation is the the competing influences of tectonic uplift and sea level change. As global sea level rose and fell, continual regional uplift kept the sea from reaching levels high enough to allow formation of units typical of high relative sea level. Only once, at the top of the third sequence, does a thin layer of high relative sea level sediments appear. Another interpretation is that thin, high relative sea level sediments were deposited, but eroded and so are not preserved in the section.





 This section can also be interpreted in terms of second-order cycles. The entire set of 17 depositional sequences can be bracketed by five second-order cycles, based on physical stratigraphy and biostratigraphy. Major biostratigraphy gaps exist at the boundaries of each second-order cycle, and the boundaries can be seen to represent major changes in the depositional style of basin fill.

If the volume of earth in a study area is small enough, workstations can add a new dimension to sequence stratigraphy. In the Green canyon area of the Gulf of Mexico, interpreters concentrated on a fan deposited in a syncline on the continental slop 1 to 2 million years ago. Regional sequence stratigraphy was established using 2D seismic data and paleontologic control from six nearby wells. Zooming in on a subset of this data, interpreters assembled a series of 2D panels for 3D interpretation.

The top and base of the slope fan were interpreted over a six-block area (138 km2). The thickest part of the slope fan coincides with the stacked channels that carried shallow-water shelf and delta sands into deep water, greater than 200 m. A series of stacked channels, possibly filled with sand, is visible within the slope fan interval.

The goal of this interpretation is to identify exploration targets. Although lithology of the channel deposits is difficult to identify in the horizon slice, geology predicts that the channel will terminate in a sand-rich fan. The channel was tracked south, and a fan was discovered in the next block of seismic data.




Sequence stratigraphy continues to evolve. One area of investigation is high resolution sequence stratigraphy, which is performed at a higher resolution than seismic wavelengths, usually with log and outcrop studies.